Use of the Secure Drilling system on a well in Mexico significantly reduced time and costs compared with previous wells. The system provides monitoring and control capabilities in enhancing MPD, which has helped operators to drill in many difficult areas worldwide, such as in carbonate reservoirs, deep drilling and deepwater drilling.

By Erdem Catak and Brian Grayson, Weatherford International Ltd

The essence of well control is information. Ideally, downhole information facilitates a knowledgeable, expert response to prevent a costly or even catastrophic well control event. But in reality, good and timely information have been difficult to acquire and apply – especially in the extremes of modern wellbores where it is needed most.

That is changing quickly. By integrating a closed-loop drilling system with real-time monitoring and automated well control capabilities, some of the world’s most difficult well control conditions are being routinely drilled – from total circulation losses in “undrillable” carbonates to threading narrow drilling windows in deepwater boreholes.

Weatherford’s Secure Drilling monitoring and control system is resolving many fundamental well control challenges to improve safety and drilling performance. Since its commercial introduction in 2006, the system has been used in more than 40 applications around the world.

CONTROL ADVANTAGES

Within the confines of a closed-loop system, bottomhole information is quickly acquired, calculated and acted on by the system. Precise monitoring of wellbore flow rates, temperatures, pressures and mud weights provides the data to control an automatic choke manifold that manages equivalent circulating density (ECD). And controlling ECD means controlling the well.

In addition, managing ECD enhances well control options and efficiency by facilitating easy transitions between conventional drilling and managed pressure drilling (MPD). These combined capabilities provide a high degree of finesse in controlling very challenging well conditions.

This includes unique capabilities for addressing common well control problems. For instance, the constant acquisition and processing of data on mud flowing into and out of the well effectively distinguishes common wellbore ballooning from a kick.

But its contribution to MPD methodologies is where the technology really excels. The inclusion of monitoring and control capabilities in MPD methodologies – which share the feature of a closed-loop drilling system and several key components – provides significant advances for a technique that is already the enabler for drilling many difficult and otherwise impossible wells. Carbonate reservoirs around the world, along with high-pressure, high-temperature (HPHT) and narrow-drilling-window wells, are among these MPD prospects. They are already realizing benefits from added monitoring and control.

In constant bottomhole pressure (CBHP) drilling, an MPD method used in deep wells, the objective is to precisely manage ECD so the correct bottomhole pressure is maintained. Automatic monitoring and control is greatly expanding the ability to operate within the very narrow drilling windows presented by these wells.

By quickly responding to constant pore pressure and fracture gradients fluctuations, the system provides the means to effectively manage ECD within the drilling window. As the parameters change, the system enables a simple transition between CBHP methods and conventional drilling. The system changes methodologies back and forth as needed for optimal performance.

For formations where total lost circulation conditions are being solved by pressurized mud cap drilling (PMCD), monitoring and control provides additional advantages. In these conditions, natural fractures (expected to take 100% of the sacrificial fluid and cuttings) sometimes plug. The resulting spike in pressure is easily confused with a kick. But instant flow measurement quickly provides the information to discern between a routine fracture close out and a well control event.

Sour gas is also easily mitigated. In the closed-loop system, the calculated gas migration rate is slightly exceeded by the carefully monitored and controlled flow rate, and the H2S gas is safely pumped into the formation along with drilling fluid and cuttings.

On a well in Mexico, the narrow pore pressure/fracture gradient window required switching the monitoring and control system to “special” mode, which enabled the operator to use the constant bottomhole pressure drilling technique.

APPLICATIONS ABOUND

These capabilities apply to current and potential prospects around the world. Many are in areas where MPD applications are already providing support.

In Asia, for instance, notoriously difficult-to-drill carbonate reservoirs have been reclassified as good prospects through the success of PMCD methodologies. Efforts here to address total lost-circulation conditions led to early advances in MPD techniques and equipment. Refinement of those proven methods with monitoring and control capabilities further leverages established advantages in drilling difficult wells.

In deep drilling operations, monitoring and control capabilities are complemented by recently introduced marine rotating control devices (RCD), the heart of a closed-loop drilling system. The devices address such complexities as risers and heave on floating structures, so helping to extend MPD advantages to extremely deepwater exploration.

For deepwater drilling, the ability to monitor and control ECD within narrow or non-existent pore pressure/fracture gradient windows is a significant capability. By addressing this core well control issue, risks and costs can be greatly reduced. Lower time and material costs incurred fighting trouble zones are one source of economy. Another is the reduction of casing points to isolate the zones, which allows the target depth to be reached with the designed hole diameter. By negating the need for big, heavy casing strings, the requirement for massive floating vessels to run them is also reduced.

RECENT FIELD EXPERIENCE

The first commercial application of the system was in August 2006 in South Texas on a McAllen Ranch project. The rough Hildalgo County area is known for HPHT wells and sour gas. Only a few months later, the new system was rigged up half-way around the world offshore Angola. Soon after the Angola well, a land well in Brazil was successfully drilled with the system.

Today, the system is being used in a variety of well control applications on wells in Venezuela, Tunisia, Pakistan, the North Sea, Mediterranean, Gulf of Mexico, West Africa and more. These applications are facilitating the drilling of highly difficult wells – often succeeding where past efforts have failed due to well control hurdles.

Drilling was just completed on a hole section in a deep land exploratory well in one of the first wildcat projects in this area of the Middle East. The hole section could not have been drilled without the monitoring and control system and its ability to constantly manage kicks. This allowed casing to be set deeper and reduced nonproductive time that otherwise would have been spent fighting the well.

A recent application offshore Egypt in the lower Mediterranean Sea resulted in the first well successfully drilled in the region’s difficult HPHT geology. Drillers in the area commonly deal with kick-loss scenarios that can add hundreds of days to the schedule. With a closed-loop circulating system installed, the monitoring and control system provided the information needed to manage the bottomhole pressure within confining pore and fracture pressure limits.

In another Middle East PMCD application, success with two previous offshore wells using automated monitoring and control capabilities has led to a third. Reliable control provided the confidence to both the operator and the rig contractor to drill despite high-pressure H2S gas and lost returns. The kick-loss scenario was complicated by migration of the hazardous sour gas in the annulus during pauses in the PMCD operations.

The ability to monitor fluid flow and control pressure was critical to the decision to proceed with the well. Measuring flow around the clock allowed development of a pressure signature that distinguished kicks from flow variations caused by differences in the rate at which the formation accepted fluids.

Gas migration was solved by pumping it back in to the formation. Based on the calculated rate of gas migration in the annulus, flow was managed so it slightly exceeded the gas rate. This produced a slight flow into the well, which stopped the gas from rising and moved it back downhole, where it was injected into the formation along with the sacrificial drilling fluid and cuttings. Having a control system that could ensure a constant loss rate was the key to achieving this success.

In Mexico, confidence in controlling the well led to a longer casing run and a bigger completion size. A high-pressure zone was anticipated in the casing plan. Below it was the lower pressure reservoir. Mud weight was 9.5 lb as the bit neared the high-pressure section, where a pore pressure of 12.7 lb was predicted. The decision was made to continue drilling based on the assurance that the automated system could manage a kick.

The system was initially used in the standard “auto-kick detection and control” mode, which enabled the identification of swab and surge caused by drillstring movement. Based on this identification, it was recommended that the tripping speed be reduced in order to reduce the resultant pressure spikes.

As the well progressed, the system showed that the displacement of drilling mud was not corresponding to the volume of the drillstring being tripped into the wellbore. This signaled that fluid losses were occurring and drilling mud was being injected into the formation. The margins between pore and fracture gradients required the system to be transitioned into a special mode that is equivalent to the constant bottomhole pressure drilling technique. This transition required only the use of an auxiliary pump and, in this case, an existing rig pump was used.

The system allowed for continuous control of the well by monitoring the flow and pressures; optimized tripping speeds to avoid swab and surge; and quick detection of losses. This allowed the entire section to be drilled with no kick – no high-pressure zone. The benefits of the system were compounded by the inability to use downhole tools due to high temperatures. Confidence in the system saved a casing point and allowed the reservoir to be drilled with a bigger bit and completed more efficiently than previous wells using conventional drilling methods.

East Texas gas wells drilled using the system have effectively identified high-pressure kicks, allowing the wells to be shut in to avoid an event. For example, the latest well, located in a residential area, took a kick while making connections.

The well was overbalanced with the pumps on. When the pumps were stopped, the well lost about 200 psi of friction pressure. Flow was being monitored, and it was going down as expected. But then it was observed to be increasing, and the well was shut in. In the three minutes it took from pump stop to shut-in, the well gave 35 bbl of kick. Without the ability to see the flow immediately and know to close the BOP, the kick could have resulted in a major well control event and loss of the rig, an all-too-common outcome in the area.

SYSTEM BASICS

This degree of control is achieved with a small equipment footprint consisting of only a few components that integrate seamlessly with standard rig operations. Fundamental to monitoring and control is the closed-loop circulating system made possible by an RCD installed on top of the BOP stack. Managing the annular flow of fluids at the surface (as opposed to the unrestricted flow in conventional open-loop systems) affords a high degree of control over downhole events.

The system monitors either end of the closed-loop system to provide previously unobtainable accuracy and immediacy. Mud flow, standpipe pressure and density are measured on the way into the well. Returning annular mud is pumped through an automated drilling choke manifold, which regulates the degree of backpressure on the system. An inline flow meter and sensor capture data on mass flow, volume flow, mud weight and temperature in real time at a sample rate of three times per second.

The system’s intelligent control unit applies proprietary algorithms to identify minute downhole fluid influxes and losses. These changes are contrasted with a well hydraulics model to provide information at the operator’s panel and to the intelligent controller to affect choke manifold settings.

In addition to this proactive, automated well control, the system’s measurement of mud weight provides immediate information on gas cut, barite settling and cuttings deposition.

All of this information is viewed at the operator interface, where changes to the choke manifold settings may be made. But the system typically operates independently according to parameters input into the automated control system. The only required intervention is often a matter of updating the model parameters.

Like the autopilot on an airplane, the system still requires expert supervision to address unanticipated conditions and ensure proper operation. But the ultimate vision is that this will be handled by drilling personnel – much as RCD operations are becoming a standard part of the rig equipment package on US land rigs operated and maintained by the rig crew.

ROUTINE WELL CONTROL

Well control in difficult well environments depends on fast, actionable information. The ability to provide this control is being achieved in closed-loop circulating systems equipped with unique monitoring and control technology. Used simply to alert personnel to a kick, or to greatly enhance MPD methodologies, this monitoring and control technology provides the means to safely and efficiently drill challenging wells and opens the door for success in even more difficult well control circumstances.

Erdem Catak is global product line manager of Secure Drilling Systems and Brian Grayson is global product line manager of Controlled Pressure Drilling.

1 Comments For This Post

Dear sir,
After our residential well ran nearly dry, we had a new well drilled last week. At 500′ drillers hit an artesian spring and we now have plenty of water. However, water continues to trickle into the yard from underneath the capped 6″ pipe. A temporary solution the driller suggested is to let the water run as much as possible.
Although this seems too much like “wasting water”, we’ve complied, and, after attaching a hose to an outdoor faucet, have let the water drain into the nearby woods at night. We shut off the faucet in the daytime and use water as usual, but, by nightfall, the trickle begins again and we have to reopen the outdoor faucet for drainage. We’ve followed this procedure for five days and are seeking a permanent solution to the problem.
The driller has been searching for some kind of cap that will seal the well pipe completely and without the possibility of too much pressure build-up. We’ve already spent quite a lot of money on this project, so need a reasonably priced cap in order that the job can be completed. Also, living in central Pennsylvania as we do, we can’t continue to let excess water flow through an outdoor hose for much longer.
Can you suggest a cap that would solve this problem and a manufacturer where such a cap could be purchased?
Thank you for your expert advise in this matter. I would be most grateful for an expeditious reply.